Zonal communication and methods of evaluating zonal communication

ABSTRACT

Methods may include recording pressure and/or temperature data at two or more time points in a region adjacent an isolated zone in a wellbore created by one or more isolation devices; and determining the degree of fluid communication around the one or more isolation devices from characteristic changes in the recorded pressure and/or temperature data. Methods may also include injecting a fluid into an isolated zone in a wellbore created by one or more isolation devices; recording pressure and/or temperature data at two or more time points in a region adjacent the isolated zone; and determining the degree of fluid communication around the one or more isolation devices from characteristic changes in the recorded pressure and/or temperature data.

BACKGROUND

Following the cessation of drilling operations, completions may be initiated in which downhole tubulars and equipment are installed to enable the safe and efficient production from an oil or gas well. During completions, sections of casing or pipe string may be placed into the wellbore to enhance wall strength and minimize the chances of collapse, burst, or tensile failure. Well casings of various sizes may be used, depending upon depth, desired hole size, and types of geological formations encountered. The casing and other tubulars may, in some instances, be stabilized and bonded in position using various physical and chemical techniques.

Following completions, stimulation operations may be conducted by initiating fractures or through the use of treatments such as acids and other chemicals that increase the porosity of the formation. Fracturing operations conducted in a subterranean formation may enhance the production of fluids by injecting pressurized fluids into the wellbore to induce hydraulic fractures and introducing flow channels that connecting isolated reservoirs. Fracturing fluids may deliver various chemical additives and proppant particulates into the formation during fracture extension. Following the injection of fracture fluids, introduced proppants may prevent fracture closure as applied pressure decreases below the formation fracture pressure. The propped open fractures then allow fluids to flow from the formation through the proppant pack to the production wellbore.

SUMMARY

This summary is provided to introduce a selection of concepts that are described further below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In one aspect, embodiments in accordance with the present disclosure may be directed to methods that include recording pressure and/or temperature data at two or more time points in a region adjacent an isolated zone in a wellbore created by one or more isolation devices; and determining the degree of fluid communication around the one or more isolation devices from characteristic changes in the recorded pressure and/or temperature data.

In another aspect, embodiments in accordance with the present disclosure may be directed to methods that include injecting a fluid into an isolated zone in a wellbore created by one or more isolation devices; recording pressure and/or temperature data at two or more time points in a region adjacent the isolated zone; and determining the degree of fluid communication around the one or more isolation devices from characteristic changes in the recorded pressure and/or temperature data.

Other aspects and advantages of the disclosure will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF FIGURES

FIG. 1 is an illustration of a completion operation in which cement is installed in an annular region created between a borehole and an installed casing in accordance with embodiments of the present disclosure.

FIG. 2 is an illustration of a zone isolated during a completions operation in accordance with embodiments of the present disclosure.

FIG. 3 is a graphical representation of representative data measured in a region adjacent an isolated interval in accordance with embodiments of the present disclosure.

FIG. 4 is an illustration of an interval experiencing near-wellbore communication from an isolated zone during a completions operation in accordance with embodiments of the present disclosure.

FIG. 5 is a graphical representation of representative data measured in a region adjacent an isolated interval experiencing near-wellbore communication in accordance with embodiments of the present disclosure.

FIG. 6 is an illustration of an interval experiencing far-wellbore communication from an isolated zone during a completions operation in accordance with embodiments of the present disclosure.

FIG. 7 is a graphical representation of representative data measured in a region adjacent an isolated interval experiencing far-wellbore communication in accordance with embodiments of the present disclosure.

FIG. 8 is a flow diagram illustrating a method of determining the presence of zonal communication in accordance with embodiments of the present disclosure.

FIG. 9 is an illustration of a computer system in accordance with embodiments of the present disclosure.

DETAILED DESCRIPTION

In one aspect, methods in accordance with embodiments disclosed here may be directed to the detection and quantification of zonal communication following wellbore completion and cementing. Methods in accordance with the present disclosure may monitor changes in pressure and/or temperature in regions adjacent zones isolated during completions and production to detect near- and far-wellbore fluid communication. In one or more embodiments, methods may allow early identification and mitigation of zonal communication severity, which may allow an operator to address potential problems and employ remedial measure such as modification of stimulation protocols including reducing injection rates, resetting packers, or the use of diverting treatments or fluid loss materials.

Following the cessation of drilling operations, cementing may proceed by casing the wellbore and emplacing a cement slurry into an annulus created between a wall of the formation and a section of installed casing (or an annulus between casing strings). With particular respect to FIG. 1, a derrick 100 is shown installed on a wellbore 101 traversing a formation 102. Within the wellbore 101 concentric segments of casing 104 are nested within each other, in preparation for installation of a cement sheath between the outside of the casing and the exposed formation and/or other emplaced casing strings. During the cementing operation, a cement slurry 106 is pumped into an annulus formed between formation 102 and the casing 104. In some embodiments, cement slurry may be pumped into multiple annular regions within a wellbore such as, for example, (1) between a wellbore wall and one or more casing strings of pipe extending into a wellbore, or (2) between adjacent, concentric strings of pipe extending into a wellbore, or (3) in one or more of an A- or B-annulus (or greater number of annuli where present) created between one or more inner strings of pipe extending into a wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string.

In some cases, wellbores may be stimulated after completions using a number of stimulation techniques such as “plug and perf” in which the casing of the wellbore is perforated using projectiles or abrasive jetting to allow reservoir fluids to enter the wellbore. During stimulation, a wellbore may be perforated in a number of different locations in order to increase production, either in the same hydrocarbon-bearing zone or in different hydrocarbon-bearing zones, and thereby increase the flow of hydrocarbons into the well. With particular respect to FIG. 2, a wellbore 202 may traverse one or more zones of interest 204 within a subterranean formation. In order to access the zones of interest 204, a perforating tool may be lowered into the wellbore to create perforations 208 through a cemented casing 206 and into the near wellbore.

Stimulation may target single or multiple zones within the well at time through the use of various technologies. For example, a wellbore may subdivided into a number of isolated zones and individual zones may be stimulated in a controlled sequence, such as from the toe of the well to the heel, using various treatment fluids until all zones are treated. Stimulation techniques may involve multiple steps such as running a perforating gun down the wellbore to one or more target zones, perforating the target zones, removing the perforating gun, treating the target zones with a hydraulic fracturing fluid, and then isolating the perforated target zones for subsequent production.

Completion operations may utilize the installation of isolation devices inside the casing and/or liner to isolate one or more target zones for stimulation or production from the remainder of the well. In some embodiments, zones may be isolated with a packer 210 emplaced on a string of tubing 207. Other isolation devices in accordance with the present disclosure may include tension packers, compression packers, hydraulic-set packers, plugs such as bull plugs, bridge plugs, darts, and the like. Isolation devices may also include packers offered commercially as a component of BROADBAND™ Precision available from Schlumberger Technology Corporation. In some embodiments, intelligent completions may be used, which may involve the use of liner systems, packers, subsurface flow controls, and subsurface safety valves. Completion systems may also incorporate both sensing and control systems, inflow control devices (ICDs), flow control valves (FCVs), pressure gauges, and control lines that may allow users to drain their reservoirs with granularity and may provide an increased feedback regarding fluid movement and reservoir drainage.

However, the use of isolation techniques and intelligent completion systems within the wellbore may have limited effectiveness in situations in which the cementing job behind the casing that isolates the sections from the formation is incomplete or defective. Fluid communication in the near- and far-wellbore may not be evident during primary cementing, and cement characterization methods are uncommon prior to production due to the added time and costs. Inadequate characterization of fluid communication may lead to uncertainty with regard to the level of fluid communication between zones, which can lead to the diversion of treatment fluids beyond installed isolation devices during stimulation and loss of pressure control, overflushing at elevated pressures, and infliction of formation damage or stimulation of collateral intervals around the target. Further, during production, pressure imbalances between neighboring stages (or laterals in a multilateral well) may result in a higher pressure stage disemboguing into a lower pressure stage rather than to the surface, potentially damaging the zone and limiting production. In another example, fluid communication may allow stages closer to the heel of the well that produce water to contaminate hydrocarbon streams transported from the toe of the well.

Returning to FIG. 2, monitoring of zonal fluid communication in accordance with embodiments of the present disclosure may involve the emplacement of a tool string including one or more measuring modules 212 arranged adjacent a packer 210. Packer 210 may be engaged once in place at the target region, creating an isolated zone 216 within the wellbore. The isolated zone may then be stimulated using various physical and chemical techniques and/or produced for hydrocarbons and connate fluids. In some embodiments, measuring module 212 may be activated to measure pressure and/or temperature in the regions of the well (such as 214) isolated from fractured interval 208 to quantify the degree of fluid communication. In some embodiments, sleeves 205 present on a toolstring or coiled-tubing 207 may be engaged, allowing the injection of treatment fluids into the isolated zone and/or to allow production fluids to be transported through the tubing 207 to the surface.

Measuring modules 212 may communicate pressure and/or temperature data to the surface using any suitable downhole-to-surface transmitting technology, including the use of pressure pulses similar to that employed during logging-while-drilling (LWD), wireline, i-coil, fiber-optics, and the like. In some embodiments, the measuring module may incorporate a memory gauge that samples and records downhole pressures or temperatures, with the data being stored, ready for downloading to acquisition equipment when the tool assembly has been retrieved to surface. In some embodiments, data transmission from the measuring module may occur in real time, which may enable an operator to monitor fluid communication during stimulation operations or production. While a number of data transmission techniques are discussed, it is envisioned that any technology capable of relaying pressure and temperature data to an operator remote from the measurement location may be employed.

Zonal communication may be monitored in accordance with the present disclosure by measuring the conditions in areas adjacent an isolated region of the wellbore to detect fluid communication in through near- and far-wellbore channels. With particular respect to FIG. 3, a graphical representation of data received is presented from a measuring module arranged as depicted in FIG. 2. During stimulation, fluids injected into isolated zone 216 may be communicated into adjacent region 214 containing measuring module 212, which creates environmental changes that are detectable by the measuring module 212. When isolated properly, fluid flow from isolated region 216 is minimal and ambient formation temperatures heat the static fluid column in adjacent zone 214 over time, as indicated by the solid black trace in FIG. 3. Similarly, in situations having no fluid communication, wellbore fluids outside of the isolated region 216 slowly depressurize in the absence of the applied pressure of pumped fluids, as indicated by the dashed trace in FIG. 3.

In one or more embodiments, one or more additional measuring modules may be arranged above the isolated region. For example, pressure and temperature gauges (including memory gauges) may be installed above and below isolation packer to determine differential pressures and temperatures across the packer. In some embodiments, completions systems containing multiple pressure and temperature gauges may include commercial completions systems such as BROADBAND PRECISION™ available from Schlumberger Technology Corporation.

Fluid communication around isolated zones may exhibit characteristic and measurable changes in pressure and temperature in zones adjacent isolated intervals. For example, fluid communication may be evident by observing the magnitude of differential in bottom hole pressure (BHP) and/or bottom hole temperature (BHT). When fluids are injected into or drained from the isolated interval, escaping fluids enter adjacent zones and increase the fluid volume and measured pressure. Further, measurable changes in temperature may be observed as cooler fluids migrate from the isolated zones and/or exchange with warmer, less dense, fluids from the adjacent zones.

Pressure differentials in accordance with the present disclosure may be within a lower limit of greater than 0 psi or 10 psi to an upper limit of any of 5000 psi, 2000 psi, or 1000 psi, where any lower limit can be used with any upper limit. In some embodiments, the pressure differential may be within a lower limit of any of −5000 psi, −2000 psi, or −1000 psi to an upper limit of −100 psi or less than 0 psi, where any lower limit can be used with any upper limit.

Temperature differentials in accordance with the present disclosure may be within the range of a lower limit of greater than 0° C. or 2° C. to an upper limit of 100° C., 50° C., or 10° C., where any lower limit can be used with any upper limit. In some embodiments, the temperature differential may be within a lower limit of any of −100° C., −50° C., or −10° C. to an upper limit of −2° C. or less than 0° C., where any lower limit can be used with any upper limit.

For example, near-wellbore communication, occurring in the first few feet from the axis of the well such as near the casing and formation wall and/or through a cement annulus, may allow fluids to pass around isolation devices emplaced within the wellbore. With particular respect to FIG. 4, defects in primary cementing jobs may result in the formation of channels and microannuli that allow fluid communication through the near-wellbore area 402 or through cracks within the cemented interval 404. In one or more embodiments, fluid communication from the isolated zones may be may be identified by monitoring changes in temperature in pressure in the adjacent zones. During near-wellbore communication, diversion of injected or produced fluids may migrate into an adjacent zone below an installed packer, which may be measured using a measuring module that monitors changes in pressure and temperature. With particular respect to FIG. 5, fluid communication in the near-wellbore region may be characterized by increases in pressure (dashed trace) and increases in temperature (solid trace) over relatively short time scales following the injection or production of fluids within the isolated interval.

Fluid communication may also exist in the far-wellbore regions, and occur deeper in the formation. With particular respect to FIG. 6, depending on a number of factors, including the nature of the formation and the use of intervention techniques such as stimulation by acidization or perforation, fractures and other defects may extend and connect to form channels that enable far-wellbore fluid communication 602. Far-wellbore communication may be characterized by changes in temperature and pressure that occur over longer time scales than near-wellbore communication. With particular respect to FIG. 7, a graphical representation of pressure (dashed trace) and temperature (solid trace) as a function of time shows a slow increase in pressure as fluids are diverted from the isolated zones into the formation and back to the adjacent zones containing the measuring module. Temperature changes in far-wellbore communication may be less dramatic when compared to the near-wellbore case as diverted fluids are equilibrated to formation temperature as the fluid is redirected to the adjacent zone.

Methods in accordance with the present disclosure are directed to identifying and addressing zonal communication by measuring pressure and/or temperature downhole during completion and production. With particular respect to FIG. 8, a flow diagram depicting an embodiment of a method for detecting fluid communication is shown. Methods in accordance with the present disclosure may begin following the isolation of one or more intervals of a wellbore at 802 using various isolation technologies. Following the initial zonal isolation, a measurement module, installed proximate to and on a side opposing the isolated interval created by the emplaced isolation device, is used to record data, such as pressure and temperature, in the non-isolated region of the wellbore at 804. Data recording may occur during a stimulation or production process. For example, data recording may follow the stimulation of an isolated stage, prior to the creation and or stimulation of additional frac stages within the wellbore in some embodiments.

Data measured during a selected wellbore operation, which may include temperature and/or pressure data, may then be evaluated to determine whether characteristic changes in the measured data correspond to patterns established for the presence of near- and far-wellbore communication at 806. Data measurements may include the magnitude of change in temperature and pressure at two or more time points, which may be obtained in real time during wellbore operations in some embodiments. Fluid communication levels quantified at 806 may then be used by an operator at 808 to adjust the current completion design or to initiate remedial operations to improve zonal isolation prior to subsequent operations. Adjustment of completion or production design may include pumping isolation pills designed to plug communication channels, changing treatment volume, adjusting pumping rates, and the like.

Embodiments of the present disclosure may be implemented on a computing system. Any combination of mobile, desktop, server, embedded, or other types of hardware may be used. For example, as shown in FIG. 16, the computing system (1600) may include one or more computer processor(s) (1602), associated memory (1604) (e.g., random access memory (RAM), cache memory, flash memory, etc.), one or more storage device(s) (1606) (e.g., a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, a flash memory stick, etc.), and numerous other elements and functionalities. The computer processor(s) (1602) may be an integrated circuit for processing instructions. For example, the computer processor(s) may be one or more cores, or micro-cores of a processor. The computing system (1600) may also include one or more input device(s) (1610), such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device. Further, the computing system (1600) may include one or more output device(s) (1608), such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device), a printer, external storage, or any other output device. One or more of the output device(s) may be the same or different from the input device(s). The computing system (1600) may be connected to a network (1612) (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, mobile network, or any other type of network) via a network interface connection (not shown). The input and output device(s) may be locally or remotely (e.g., via the network (1612)) connected to the computer processor(s) (1602), memory (1604), and storage device(s) (1606). Many different types of computing systems exist, and the aforementioned input and output device(s) may take other forms.

Software instructions in the form of computer readable program code to perform embodiments of the present disclosure may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium. Specifically, the software instructions may correspond to computer readable program code that when executed by a processor(s), is configured to perform embodiments of the present disclosure.

Further, one or more elements of the aforementioned computing system (1600) may be located at a remote location and connected to the other elements over a network (1612). Further, embodiments of the present disclosure may be implemented on a distributed system having a plurality of nodes, where each portion of a computer system in accordance with the present disclosure may be located on a different node within the distributed system. In one embodiment of the present disclosure, the node corresponds to a distinct computing device. Alternatively, the node may correspond to a computer processor with associated physical memory. The node may alternatively correspond to a computer processor or micro-core of a computer processor with shared memory and/or resources.

Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods and uses, such as are within the scope of the appended claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function. 

What is claimed is:
 1. A method comprising: recording pressure and/or temperature data at two or more time points in a region adjacent an isolated zone in a wellbore created by one or more isolation devices; and determining the degree of fluid communication around the one or more isolation devices from characteristic changes in the recorded pressure and/or temperature data.
 2. The method of claim 1, further comprising preparing a wellbore treatment to modify the determined degree of fluid communication around the one or more isolation devices.
 3. The method of claim 1, wherein the recorded pressure and/or temperature data is transmitted to the surface by one or more selected form a group consisting of pressure pulses, i-coil, and fiber optics.
 4. The method of claim 1, wherein the recorded pressure and/or temperature data is transmitted in real time.
 5. The method of claim 1, wherein pressure data is recorded and wherein a decrease in pressure over time is indicative of minimal fluid communication outside of the isolated zone.
 6. The method of claim 1, wherein pressure data is recorded and wherein an increase in pressure over time is indicative of fluid communication outside of the isolated zone.
 7. The method of claim 1, wherein temperature is recorded and wherein an increase in temperature over time is indicative of minimal fluid communication outside of the isolated zone.
 8. The method of claim 1, wherein temperature is recorded and wherein a decrease in temperature over time is indicative of fluid communication outside of the isolated zone.
 9. The method of claim 1, wherein recording pressure and/or temperature data is performed using a memory gauge.
 10. The method of claim 1, wherein recording pressure and/or temperature data is performed during stimulation of the isolated zone.
 11. The method of claim 1, wherein recording pressure and/or temperature data is performed during production of the isolated zone.
 12. A method comprising: injecting a fluid into an isolated zone in a wellbore created by one or more isolation devices; recording pressure and/or temperature data at two or more time points in a region adjacent the isolated zone; and determining the degree of fluid communication around the one or more isolation devices from characteristic changes in the recorded pressure and/or temperature data.
 13. The method of claim 12, wherein the injected fluid is a stimulating treatment.
 14. The method of claim 12, further comprising preparing a wellbore treatment to modify the determined degree of fluid communication around the one or more isolation devices.
 15. The method of claim 12, wherein pressure data is recorded and wherein a decrease in pressure over time is indicative of minimal fluid communication outside of the isolated zone.
 16. The method of claim 12, wherein pressure data is recorded and wherein an increase in pressure over time is indicative of fluid communication outside of the isolated zone.
 17. The method of claim 16, wherein the increase in pressure is characterized as a pressure differential in the range of 100 psi to 5000 psi.
 18. The method of claim 12, wherein temperature is recorded and wherein an increase in temperature over time is indicative of minimal fluid communication outside of the isolated zone.
 19. The method of claim 12, wherein temperature is recorded and wherein a decrease in temperature over time is indicative of fluid communication outside of the isolated zone.
 20. The method of claim 22, wherein the decrease in temperature is characterized as a pressure differential in the range of 2° C. to 100° C. 